Field of the Invention
This disclosure is related to the field of quicklime products and methods of manufacturing and uses thereof, specifically to compositions and methods of manufacturing and uses of compositions comprising calcium hydroxide—more commonly called hydrated lime or lime hydrate—that have quick reactivity with acids and specifically acid gases and halogenated acid gases such as sulfur trioxide.
Description of Related Art
Many efforts have been made to develop materials for improved capability of cleaning or “scrubbing” flue gas or combustion exhaust. Most of the interest in such scrubbing of flue gas is to eliminate particular compositions, specifically acid gases, that provide particularly detrimental known environmental effects, such as acid rain.
Flue gases are generally very complex chemical mixtures which comprise a number of different compositions in different percentages depending on the material being combusted, the type of combustion being performed, impurities present in the combustion process, and specifics of the flue design. However, certain chemicals which commonly appear in flue gases are known to be undesirable to have exhausted, and therefore their release is generally regulated by governments and controlled by those who perform the combustion.
Some such materials that are subject to regulation are certain acid gases. A large number of acid gases are desired to be, and are, under controlled emission standards in the United States and other countries. This includes compounds such as, but not limited to, hydrogen chloride (HCl), sulfur dioxide (SO2) and sulfur trioxide (SO3). Sulfur trioxide can evidence itself as condensable particulate in the form of sulfuric acid (H2SO4). Condensable particulate can also be a regulated emission. Flue gas exhaust mitigation is generally performed by devices called “scrubbers” that provide additional chemical compounds into the flue gas that react with the compounds to be removed either allowing them to be captured and disposed of, or allowing them to be reacted into a less harmful compounds prior to their exhaust, or both. In addition to control for environmental reasons, it is desirable for many combustion plant operators to remove acid gases from their flue gas to prevent them from forming powerful corroding compounds which can damage their flues and other equipment.
These acid gases can arise from a number of different combustion materials, but are fairly common in fossil fuel combustion (such as oil or coal) due to sulfur being present as a common contaminant in the raw fuel. Most fossil fuels contain some quantity of sulfur. During combustion, sulfur in the fuel can oxidize to form sulfur oxides. A majority is sulfur dioxide (SO2) but a small amount of sulfur trioxide (SO3) is also formed. Selective Catalyst Reduction (SCR) equipment, commonly installed for removal of nitrogen oxides (NOx) will also oxidize a portion of the SO2 in flue gas to SO3. Other components of the process (iron, etc.) can increase the amount of SO3 that forms in the flue gas. Particularly in coal combustion, where the chemical properties of the coal are often highly dependent on where it is mined, the ability to mitigate the amount of sulfur oxides in flue gas is highly desirable as it allows for lower quality raw coal (which may be less expensive to produce and more abundant) to be burned sufficiently cleanly to lessen environmental impact and impact on machinery.
SO2 is a gas that contributes to acid rain and regional haze. Since the 1970's, clean air regulations have reduced emissions of SO2 from industrial processes at great benefit to the environment and human health. For large emitters, the use of wet and dry scrubbing has led to the reduction of SO2. Smaller emitters, however, require less costly capital investment to control SO2 emissions to remain operating in order to produce electricity or steam.
Similarly, halides in fossil fuels (Cl and F) are combusted and form their corresponding acid in the flue gas emissions. The halogenated acids also contribute to corrosion of internal equipment or, uncaptured, pollute the air via stack emissions.
Mitigation, however, can be very difficult. Because of the required throughput of a power generation facility, flue gases often move through the flue very fast and are present in the area of scrubbers for only a short period of time. Further, many scrubbing materials often present their own problems. Specifically, having too much of the scrubbing material could cause problems with the plant's operation from the scrubber material clogging other components or building up of moving parts.
Some removal of SO3 occurs within the system. FIG. 1 shows an embodiment of a flue system. As flue gas cools in the Air Preheater (APH), a portion of the SO3 can deposit on the internals of the equipment. The presence of a small amount of SO3 lowers the resistivity of fly ash and is generally beneficial towards capture of ash in an electrostatic precipitator. Additional SO3 can be removed by absorption onto the fly ash in the flue or the particulate collection device.
A majority of the SO3, however, passes through the system unchecked. Remaining SO3 that continues through the APH can pass through dew point and form a sulfuric acid mist. This mist continues through the post-APH ductwork and particulate collection device. Plants equipped with a wet Flue Gas Desulfurization (FGD) system will form H2SO4 aerosols as the flue gas is quenched in the scrubber. This action results in a characteristic blue plume emitted from the stack.
The presence of SO3/H2SO4 in flue gas necessitates a variety of operation considerations. Use of wet flue gas desulfurization for SO2 control can generate a tell-tale blue plume of sulfuric acid mist that is an eyesore at best and environmental risk to the local community at worst. The primary risk of a blue plume is a touch down into neighboring areas, causing potential health effects, corrosion of property, damage to vegetation, and/or potential negative attention due to the appearance of the stack emission.
Corrosion of process equipment is also a risk. Equipment that can be affected includes duct work, fans (Air Preheater), and the internals of particulate collection devices. Process temperatures for heat recovery are dictated by acid dew point temperature of the flue gas. Ammonia slip from SCR operation can react with SO3 to form ammonium bisulfate (ABS), a sticky precipitate that clogs air heater internals.
The presence of acid gases in flue gas dictates operational decisions and increases operating costs. Minimization of SO2 conversion to SO3 may warrant the extra expense of low conversion catalyst in a SCR. Fear of forming sticky ammonium bisulfate (ABS) particles on APH internals will affect operation of the SCR in order to contain ammonia slip. The need to operate safely above dew point in the APH increases heat rate and resulting energy costs. Greater air flow due to a high heat rate translates to additional power required to run the fans. Ash release from baghouse bags can be less efficient if the acid gases are untreated. Units equipped with wet FGD will remove HCl, but the chlorides in the wet system can lead to corrosion issues or additional processing in water treatment.
Many coal-fired power plants are also faced with regulations on mercury emissions. SO3 in flue gas absorbs onto activated carbon—a common sorbent used for capture of mercury emissions—thereby lowering its ability to capture mercury. Units utilizing bituminous coal must remove SO3 before treating with activated carbon, thus the ability to remove SO3 to very low levels is necessary for units facing mercury removal requirements. There are high capital cost options such as Wet ESPs available, but those may not be capable of reducing high levels of SO3. In addition, a Wet ESP does not offer any upstream corrosion prevention.
Flue gas treatment has become a focus of electric utilities and industrial operations due to increasingly tighter air quality standards. As companies seek to comply with air quality regulations using cost-effective fuels, the need arises for effective flue gas treatment options. Alkali species based on alkali or alkaline earth metals are common sorbents used to neutralize the acid components of the flue gas. The most common of these alkalis are sodium, calcium, or magnesium-based. A common method of introduction of the sorbents into the gas stream is to use Dry Sorbent Injections. The sorbents are prepared as a fine or coarse powder and transported and stored at the use site. Dry sorbent injection systems pneumatically convey powdered sorbents to form a fine powder dispersion in the duct. The dry sorbent neutralizes SO3/H2SO4, and protects equipment from corrosion while eliminating acid gas emissions. Common sorbents used are sodium (trona or sodium bicarbonate) or calcium (hydrated lime, Ca(OH)2) based.
One proposed material for use in scrubbing of acid gases is increased use of hydrated lime. It has been established that hydrated lime can provide a desirable reaction to act as a mitigation agent.
Hydrated lime reacts with SO3 to form calcium sulfate in accordance with the following equation:SO3(g)+Ca(OH)2(s)→CaSO4(s)+H2O(g)
Hydrated lime systems are proven successful in many full scale operations. These systems operate continuously to provide Utility companies with a dependable, cost-effective means of acid gas control.
The most effective hydrated lime sorbents for Dry Sorbent Injection have high (>20 m2/g) BET surface area. Two examples of such compositions with increased BET surface areas are described in U.S. Pat. Nos. 5,492,685 and 7,744,678, the entire disclosures of which are herein incorporated by reference. These sorbents offer good conveying characteristics and good dispersion in the flue gas, which is necessary for high removal rates. Use of a higher quality, high reactivity source of hydrated lime allows for better stoichiometric ratios than previous attempts that utilized lower quality hydrated lime originally targeted for other industries such as wastewater treatment, construction, asphalt, etc. Hydrated lime is versatile in terms of injection location; removal of SO3 will occur with injection prior to SCR, prior to the Air Preheater (APH), post (APH) injection, post particulate collection injection, or any combination of these.
Removal of SO3 by a sorbent is dictated by the ability of the sorbent to contact the acid gas prior to entering the particulate collection device. The use of multiple injection sources to improve SO3 capture is an option. Sizing of the particulate collection device and ability to control the expected additional solids loading due to sorbent injection should also be examined.
These compositions specifically focus on high surface area based on the theories of Stephen Brunauer, Paul Hugh Emmett, and Edward Teller (commonly called BET theory and discussed in S. Brunauer, P. H. Emmett and E. Teller, J. Am. Chem. Soc., 1938, 60, 309, the entire disclosure of which is herein incorporated by reference). This methodology particularly focuses on the available surface area of a solid for absorbing gases—recognizing that a surface, in such circumstances, can be increased by the presence of pores and related structures. The reaction of hydrated lime with acid gas (such as SO3) is generally assumed to follow the diffusion mechanism. The acid gas removal is the diffusion of SO3 from the bulk gas to the sorbent particles. High surface area does not itself warrant a prediction in improved removals of acid gases. Specifically, high pore volume of large pores is generally believed to be required to minimize the pore plugging effect and, therefore, BET surface area has been determined to be a reasonable proxy for effectiveness of lime hydrates in removal of acid gases.
Because of this, commercially available products are currently focused on obtaining lime hydrate with particularly high BET surface areas. It is generally believed that the BET surface area really needs to be above 20 m2/g to be effective, and in many recent hydrated lime compositions the BET surface area is above 30 m2/g to attempt to continue to improve efficiency.
Much of the efficiency of Dry Sorbent Injection is dictated by the ability of the injection system to have the sorbent contact the acidic components of the flue gas. Flue gas pathways are not homogeneous in nature, as structural components of the flue, wall effects, and combustion processes provide a flue gas stream that can be stratified horizontally or vertically. It is the job of the DSI system to put the sorbent where the acid gas travels. Sorbent which does not enter the zones where acid is concentrated is free to react with other components of the flue gas or remain unreacted until removed in particulate collection or FGD Systems with short residence time (<2 sec) prior to particulate collection. FGD Systems are particularly vulnerable to reactivity issues related to the inability to fully disperse hydrated lime sorbent throughout the flue gas in the short length of flue available.
Due to dispersion inefficiencies in the flue gas, sorbents are typically added at concentrations in excess of the acid gas to be neutralized. Depending upon the flue configuration and sorbent injection system, the amount of hydrated lime to SO3 can be 1-4 moles of hydrate:mol of SO3. More challenging systems will require a treat rate as high as 5-10 moles of hydrate:mol of SO3. The excess required presents the end user with an economic disadvantage.
Further, most current Utilities that require acid gas mitigation utilize an Electrostatic Precipitator (ESP). This equipment uses electrostatic charges to drive ash in the flue gas against charged metal plates. Ash collects on the plates and then is removed (rapping) at regular intervals. ESP sizing will determine the amount of ash that can be removed. Excessive amounts of ash beyond the ESPs capacity will lead to problems with opacity limits. These limits are commonly regulated, typically ˜20% maximum opacity. Some units may also be regulated for particulate emissions. Too much ash will lead to increased particulate emissions.
Many existing ESPs were sized based upon the expected ash from the coal being used to fire the boiler. The ESPs were designed and installed prior to dry sorbent injection, so the added particulate as the result of DSI was not factored into ESP capacity. Units with undersized ESPs that have a relatively high amount of SO3 present in the flue gas can encounter operational problems due to the addition of hydrated lime sorbent injection. In some configurations, calcium reagents may increase the resistivity of the ash that collects on the ESP plates. If the resistivity is increased too much, the ESP plates will not capture ash from the flue gas, resulting in increased opacity and particulate content of the flue gas exiting the ESP. The extra particulate may not be captured in a downstream scrubber, leading to emission problems with the unit. The resistivity problem can occur with a small amount of hydrate if the ESP is marginally sized for the ash loading. If the acid gas content of the flue gas is relatively high, the amount of sorbent required to capture acid gas prior to ESP may be so high as to cause resistivity issues with an ESP even of moderate size.
Alkali sodium sorbents decrease the resistivity ash and, in some cases, may actually aid an undersized ESP. Because of the resistivity issues with ash, hydrated lime sorbents can be at a competitive disadvantage on units having high SO3 content and/or an undersized ESP for the expected ash loading.
While higher BET hydrated limes have proven effective at certain forms of scrubbing, pilot-scale evaluation of sorbent injection for removing acid gases (i.e. SO3 and HCl) showed that the high surface area hydrated lime performed no better than commercial grade hydrated lime. [Peterson, J. R., Maller, G., Burnette, A. and Rhudy. In Managing Hazardous Air Pollutants (Eds W. Chow and K. K. Connor, EPRI), 1993, pp 520-538 which is incorporated herein by reference]. The diffusion model proposed above, however, shows the removal rate is strongly dependent on injection rate, residence time, and the average diameter of sorbent particles.
While this analysis would indicate that smaller particles are better, sizes of the particles of hydrated lime as well as other sorbents can be produced to smaller sizes simply by increased or improved milling. However, the particle size distribution about the average generally depends on the manufacturing processes used to produce them and, therefore, compositions with identical averages can have different size distributions.